Full tensor micro-impedance imaging

ABSTRACT

Various systems and methods for implementing and using a full tensor micro-impedance downhole imaging tool that includes downhole emitters that induce, at azimuthally-spaced positions on a borehole wall, fields having components in three different non-coplanar directions within a formation and directionally sensitive downhole sensors that sense the components caused by each emitter. The tool further includes a downhole controller that processes signals received from the directionally sensitive downhole sensors to provide a set of measurements representative of a 3×3 impedance tensor at each position.

BACKGROUND

Oil field operators demand access to a great quantity of informationregarding the parameters and conditions encountered downhole. A widevariety of logging tools have been and are being developed to collectinformation relating to such parameters as position and orientation ofthe bottom hole assembly, environmental conditions in the borehole, andcharacteristics of the borehole itself as well as the formations beingpenetrated by the borehole. Among such tools are resistivity loggingtools, which measure the electrical resistivity of a formation within aborehole. These tools cause electrical currents to flow within theformations to determine the formation's resistivity. A high resistivitymeasurement within a porous formation can indicate that hydrocarbons arepresent in the formation.

The electrical resistivity of a formation is generally anisotropic,i.e., the formation's resistivity will vary depending upon theorientation of an electrical current flowing through the formation. Themeasurements obtained by a resistivity logging tool may thus varydepending upon the orientation of the current induced in the formationand used by the tool to measure the formation's resistivity. Further,both macro-anisotropy (i.e., anisotropy caused by differing formationlayers) and micro-anisotropy (i.e., anisotropy caused by the grains thatmake up the material of each layer) may both be present. Themicro-anisotropy of a given formation layer, however, may not bedetectable by resistivity logging tools with measurement resolutionsmeasured in feet or meters, rather than inches or centimeters. Such lowresolution tools may thus not fully characterize the anisotropy of theformation at both a micro and a macro level, producing an incomplete andpossibly misleading characterization of the formation.

BRIEF DESCRIPTION OF THE DRAWINGS

Accordingly, there are disclosed in the drawings and the followingdetailed description specific embodiments of full-tensor micro-impedanceimaging tools and methods. In the drawings:

FIG. 1 shows an illustrative logging while drilling environment.

FIG. 2 shows an illustrative wireline logging environment.

FIG. 3 shows an illustrative tubing-conveyed logging environment.

FIGS. 4A-4B show illustrative logging while drilling and wirelinelogging tools.

FIG. 5 shows an illustrative transducer pad.

FIGS. 6A-6C show an illustrative sequencing of transducers.

FIG. 7 graphs an illustrative sequencing of transducers.

FIG. 8 shows an illustrative inductive transducer pad.

FIG. 9 shows an illustrative galvanic transducer pad.

FIG. 10 shows an illustrative computer and data acquisition system.

FIG. 11 shows an illustrative data flow for deriving anisotropy data.

FIG. 12 shows an illustrative set of graphical borehole logs.

FIG. 13 shows an illustrative method for operating an electricalanisotropy borehole imaging system.

It should be understood, however, that the specific embodiments given inthe drawings and detailed description do not limit the disclosure. Onthe contrary, they provide the foundation for one of ordinary skill todiscern the alternative forms, equivalents, and modifications that areencompassed together with one or more of the given embodiments in thescope of the appended claims.

DETAILED DESCRIPTION

The paragraphs that follow describe illustrative full tensormicro-impedance imaging tools and systems, as well as methods for usingsuch tools and systems. Various environments suitable for the use ofthese tools, systems and methods are first described, followed by twoexample tools. The emitter/sensor pads of these tools are thenfunctionally described, and specific inductive and galvanic transducerpad embodiments are subsequently described. Illustrative galvanicelectrode configurations are also shown and described. An illustrativesystem, including both surface and downhole components, is thendescribed together with the flow of data through the system thatproduces the imaging data. Examples illustrate how the imaging data maybe presented as one or more graphical logs. Finally, an illustrativemethod for using the described tools and systems is described.

FIG. 1 shows an illustrative logging while drilling (LWD) environment. Adrilling platform 2 supports a derrick 4 having a traveling block 6 forraising and lowering a drill string 8. A kelly 10 supports the drillstring 8 as it is lowered through a rotary table 12. A drill bit 14 isdriven by a downhole motor and/or rotation of the drill string 8. As bit14 rotates, it creates a borehole 16 that passes through variousformations 18. A pump 20 circulates drilling fluid through a feed pipe22 to kelly 10, downhole through the interior of drill string 8, throughorifices in drill bit 14, back to the surface via the annulus arounddrill string 8, and into a retention pit 24. The drilling fluidtransports cuttings from the borehole into the pit 24 and aids inmaintaining the borehole integrity.

An LWD tool 26 is integrated into the bottom-hole assembly near the bit14. As the bit extends the borehole through the formations, logging tool26 collects measurements relating to various formation properties aswell as the tool orientation and various other drilling conditions. Thelogging tool 26 may take the form of a drill collar, i.e., athick-walled tubular that provides weight and rigidity to aid thedrilling process. A telemetry sub 28 may be included to transfermeasurement data to a receiver within surface module 30, which forwardsthe data to computer system 31 for further processing. Telemetry sub 28may also receive commands from surface module 30 originated fromcomputer system 31. Data and/or commands may be transferred betweensurface module 30 and computer system 31 wirelessly (as shown), or viaelectrical conductors and/or optical cables (not shown).

At various times during the drilling process, the drill string 8 may beremoved from the borehole as shown in FIG. 2. Once the drill string hasbeen removed, logging operations can be conducted using a wirelinelogging tool 34, i.e., a sensing instrument sonde suspended by a cable42 deployed from reel 43 and having conductors for transporting power tothe tool and telemetry from the tool to the surface (as shown). Awireline logging tool 34 may have pads and/or centralizing springs (notshown) to maintain the tool near the axis of the borehole as the tool ispulled uphole. The pads may also house transducers used to determine atleast some characteristics of the surrounding formation, as described inmore detail below. A surface logging facility 44 collects measurementsfrom the logging tool 34, and includes a surface module 30 coupled tospool 43 and a computer system 45 for processing and storing themeasurements gathered by the logging tool. In at least some alternativeembodiments, telemetry may be communicated between the tool and computersystem 45 wirelessly (not shown).

An alternative logging technique is logging with coil tubing. FIG. 3shows an illustrative coil tubing-conveyed logging system in which coiltubing 54 is pulled from a spool 52 by a tubing injector 56 and injectedinto a well through a packer 58 and a blowout preventer 60 into the well62. (It is also possible to perform drilling in this manner by drivingthe drill bit with a downhole motor.) In the well, a supervisory sub 64and one or more logging tools 65 are coupled to the coil tubing 54 andoptionally configured to communicate to a surface computer system 66 viainformation conduits or other telemetry channels (e.g. via electricalconductors, optical fibers, or wirelessly). An uphole interface 67 maybe provided to exchange communications with the supervisory sub andreceive data to be conveyed to the surface computer system 66.

Surface computer system 66 of FIG. 3 is configured to communicate withsupervisory sub 64 during the logging process or alternativelyconfigured to download data from the supervisory sub after the toolassembly is retrieved. Surface computer system 66 is preferablyconfigured by software (shown in FIG. 3 in the form of removable storagemedia 72) to process the logging tool measurements. System 66 includes adisplay device 68 and a user-input device 70 to enable a human operatorto interact with the system software 72.

In each of the foregoing logging environments, the logging toolassemblies preferably include a navigational sensor package thatincludes directional sensors for determining the inclination angle, thehorizontal angle, and the rotational angle (a.k.a. “tool face angle”) ofthe bottom hole assembly. As is commonly defined in the art, theinclination angle is the deviation from vertically downward, thehorizontal angle is the angle in a horizontal plane from true North, andthe tool face angle is the orientation (rotational about the tool axis)angle from the high side of the borehole. In accordance with knowntechniques, directional measurements can be made as follows: a threeaxis accelerometer measures the earth's gravitational field vectorrelative to the tool axis and a point on the circumference of the toolcalled the “tool face scribe line”. (The tool face scribe line istypically drawn on the tool surface as a line parallel to the toolaxis.) From this measurement, the inclination and tool face angle of thelogging assembly can be determined. Additionally, a three axismagnetometer measures the earth's magnetic field vector in a similarmanner. From the combined magnetometer and accelerometer data, thehorizontal angle of the logging assembly can be determined. Theseorientation measurements, when combined with measurements from motionsensors, enable the tool position to be tracked downhole.

In these and other logging environments, measured parameters are usuallyrecorded and displayed in the form of a log, i.e., a two-dimensionalgraph showing the measured parameter as a function of tool position ordepth. In addition to making parameter measurements as a function ofdepth, some logging tools also provide parameter measurements as afunction of rotational angle. Such tool measurements can be displayed astwo-dimensional images of the borehole wall, with one dimensionrepresenting tool position or depth, the other dimension representingazimuthal orientation, and the pixel intensity, pattern or colorrepresenting the parameter value.

Among the measured parameters that may be presented as part of a log areresistivity measurements, which can include measurements that reflectthe anisotropy of the borehole formation. Such measurements include, butare not limited to, vertical resistivity, horizontal resistivities inone or more directions, formation dip and formation strike. FIGS. 4A-4Bshow illustrative downhole tools suitable for taking such measurements.Illustrative LWD tool 400A (FIG. 4A) includes an array 402 oftransducers 404. Each transducer 404 may include an emitter, a sensor orboth, as well as additional structures and electronics as described inmore detail below. The transducers 404 are positioned either insidecavities within drill collar 406 or embedded in non-conductive sectionsof the collar. Techniques for placing transducers on and within drillingpipes and collars are well known in the art and are not discussedfurther. Alternatively, an array 402 with fewer transducers 404 (e.g., asingle vertical line of transducers) may be used, with the timing ofmeasurements being arranged to exploit the drillstring's rotation toproduce measurements at multiple azimuthal locations around the boreholeas drilling proceeds.

FIG. 4B shows illustrative wireline logging tool 400B, which includeseight transducer pads 408. Each transducer pad includes transducers 404similar to those used with LWD tool 400A. Transducer pads 408 areextended from the main body 410 of wireline logging tool 400B bystandoffs that position transducer pads 408 near or against the boreholewall. This reduces the effect of the drilling fluid on the measurementsand also provides better coupling between transducers 404 and theformation. Such improved coupling, together with a reduced spacing oftransducers relative to other logging tools, helps to improve thesensitivity of the tool and the resolution of the log image produced.

FIG. 5 shows an illustrative transducer pad 500 with its rear cover 502separated from its front face 504. The interior components of transducerpad 500 are shown in a simplified form for purposes of the discussionthat follows. The illustrative components include an emitter transducerarray 520 that includes emitters 522-526, and a sensor transducer array510 that includes sensors 512-516. Each emitter transducer is configuredand oriented to operate along a specific axis. Thus, for example, ifemitter 526 is an inductive emitter, emitter 526 will produce a magneticor B-field within the formation in front of transducer pad 500 with anorientation substantially along the Z axis (vertical). Similarly, eachsensor transducer is also configured and oriented to operate along aspecific axis. Thus, for example, if sensor 514 is an inductive sensor,sensor 514 will be most sensitive to B-fields within the formation withan orientation along the X axis (i.e., perpendicular to front face 504).These orientations of emitters and sensors also apply to the electricfield orientations induced and sensed within the formation by capacitiveemitters and sensors, and to the orientations of electric currentsinjected into and sensed within the formation by galvanic emitters andsensors. Although shown as separate elements for purposes of the presentdiscussion, in at least some embodiments a single multi-axial emitterand a single multi-axial sensor may be implemented to emit and senseseparable electric fields, magnetic fields or electrical currents inmore than one direction.

Continuing to refer to FIG. 5, by configuring the emitters and sensorsas shown it is possible to generate multiple sets of independentmeasurements, each set including multiple concurrent measurements. Morespecifically, the orthogonal configuration of the emitters and sensorsshown allows three sets of three measurements each to be acquired for agiven borehole depth and azimuth angle, generating nine samplesorganized as a 3×3 measurement tensor. It should be noted that the sameconcept can also apply for non-orthogonal sensors, as long as theexcitations generated are linearly independent (i.e., non-coplanar).Non-orthogonality can be incorporated by including it in a forward modeland an inversion process (both described in more detail below), or bysynthesizing orthogonal signals by rotation and using the orthogonalprocessing algorithms. Each set can be generated by separatelyenergizing and de-energizing each emitter in turn while acquiringconcurrent samples from each of the three sensors for the time periodduring which each emitter is energized. An example of such a sequence isshown in FIGS. 6A through 6C, and graphed in FIG. 7.

In FIG. 6A, energized emitter 524 (shown highlighted) induces atime-variant B-field 602 within the surrounding formation primarilyalong the X axis. As B-field 602 extends into the anisotropic formation,it begins to curve in the other two directions, which does produce somecomponents in the Y and Z directions. As a result, each of the threeenabled sensors 512, 514 and 516 (also highlighted) detect a respectivetime-variant B-field along the X, Y and Z axes, each with differingmagnitudes. This is reflected in the graph of FIG. 7 during sampleperiod T1, wherein the B-field induced by the X emitter (Emit X) isdetected primarily by the X sensor (Sens X), with detectablecontributions measured by the Y and Z detectors (Sens Y and Sens Z).Once samples have been acquired during sample period T1, the X emitteris de-energized and the Y emitter is energized, as shown in FIG. 6B.This time a B-field 604 is induced that is oriented primarily along theY axis. The resulting detected signals by the X, Y and Z sensors areshown in FIG. 7 during sample period T2. The sequence is again repeatedalong the Z axis to produce B-field 606 as shown in FIG. 6C, with theresulting detected signals shown in FIG. 7 during sample period T3.

The foregoing measurement technique employs a time-multiplexingprinciple to separate the effects of the various emitters. Othermultiplexing principles would also be suitable, including frequencymultiplexing and code-division modulation.

FIG. 8 shows an illustrative tri-axial micro-inductive transducer pad800 that operates as described above. Within emitter 820, emitterelectronics module 822 couples to and drives each of the emitter coils824 with an alternating current, under the control of other electronicsand/or software within the tool body (not shown) to which emitterelectronics module 822 also couples. The illustrated emitter coils arecoupled to a common node and positioned such that the time-variantB-field produced by one emitter coil is orthogonal to the time-variantB-fields of the other two emitter coils. In at least some embodiments,two of the emitter coils are oriented such that their B-fields areparallel to the pad surface facing the borehole wall (or with theirB-fields tangential to at least one common point on the pad surface forcurved pads). Sensor electronics module 812 within sensor 810 issimilarly coupled to each of sensor coils 814, and receives electricalsignals from the sensor coils that are induced by the B-fields producedby emitter coils 824 within the formation. Each of the sensor coils 814are also coupled to a common node and are also oriented orthogonallywith respect to each other so as to match the orientations of theemitter coils along each of the X, Y and Z axes. Sensor electronicsmodule 812 also couples to other electronics within the tool body andforwards the detected signals generated by sensor coils 814 to the toolbody electronics for further processing.

It should be noted that although emitter 820 and sensor 810 areimplemented using individual coils, those of ordinary skill willrecognize that other structures and configurations such as, for example,dipoles and phased arrays may be suitable for use within the emittersand sensors described herein, and all such structures and configurationsare within the scope of the present disclosure.

Continuing to refer to FIG. 8, within sensor 810, sensor electronicsmodule 812 also couples to bucking coils 816, which are also orientedand coupled to each other in a manner similar to the coils within sensor814. Each of sensor coils 816 is, however, wound in the oppositedirection relative to the corresponding sensor coil 814, though theirorientations are matched along each of the X, Y and Z axes. Buckingcoils 816 are also positioned proximate to sensor coils 814 and betweensensor coils 814 and emitter coils 824. Bucking coils 816 thus generatea signal for each orientation that is opposite in polarity from thecorresponding signal from sensor coils 814. In at least someembodiments, the number of turns in each bucking coil is adjusted toaccount for the difference in the distances between bucking coils 816and emitter coils 824 and the distances between sensor coils 814 andemitter coils 824. As a result, the signals produced by bucking coils816 that are attributable to direct coupling with emitter coils 824 willcancel the signals produced by sensor coils 814 that are alsoattributable to direct coupling with emitter 824. Signals produced dueto coupling through the formation between emitter coils 824 and bothsensor coils 814 and bucking coils 816, however, will not cancel out anda difference signal representing the induced B-field in the formationwill be produced from the combination of the corresponding sensor coiland bucking coil signals for each orientation (X, Y and Z). Those ofordinary skill in the art will recognize that many other techniques maybe suitable for canceling the effect of direct coupling between emitterand sensor coils, and all such techniques are within the scope of thepresent disclosure.

By mounting both the sensor coils 814 and the emitter coils 824 withintransducer pad 800, and by blocking direct coupling between the sensorand emitter coils (e.g., by incorporating bucking coils 816 within thepad), it is possible to maintain a relatively small vertical spacingbetween the sensor and emitter coils and to increase the sensitivity ofthe logging tool. Sensor/emitter coils vertical spacings of one inch orless are possible with the tools, systems and methods described herein.Reductions in the vertical spacing between sensor and emitter coilsproduce a higher vertical resolution of the resulting borehole log. Thisis due to the fact that as the distance from the emitter decreases, thedirectionality of the relevant parameter (B-field, electric current,etc.) is more pronounced, i.e., the difference in magnitude of theprimary parameter component relative to the other two orthogonalcomponents increases, as shown in FIG. 7. This also increases theoverall sensitivity of the tool. Increasing the differences in suchmeasurement thus helps to uniquely identify properties such aselectrical resistivity or conductivity and electrical permittivity(i.e., the overall formation impedance) at both a macro and micro levelin specific directions with greater precision, and to thus produce afull measurement tensor such as the 3×3 measurement tensor previouslydescribed. Such a measurement tensor enables the electrical anisotropyof the surrounding formation to be characterized and quantified (e.g.,by determining the micro-impedance of the surrounding formation in eachof three orthogonal directions for each measurement sample). In at leastsome illustrative embodiments, the components of the tensor areexpressed as complex values.

The above-described techniques for producing a 3×3 measurement tensorare not limited to transducer pads that incorporate inductive emittersand sensors. Transducer pads that incorporate capacitive emitters andsensors (not shown) may be configured and operated in a manner similarto the inductive emitters and sensors, wherein time-variant electricfields (E-fields) are induced into the surrounding formation in each ofthe three orthogonal directions and similar micro-impedance measurementsamples are produced.

Galvanic emitters and sensors may also be incorporated into a transducerpad, as shown in illustrative transducer pad 900 of FIG. 9. Transducerpad 900 (shown with the pad facing forward) includes dynamicallyconfigurable electrodes organized in an array. As shown, each electrodeset 1002 includes a central electrode 1004 surrounded by one or morefocusing electrodes 1006, and each set may be operated as either anemitter or a sensor. Alternatively, selected electrodes may be hardwiredto suitable electronics as an emitter or sensor rather than beingswitched between emitter and sensor configurations. The dynamicconfiguration enables a greater flexibility, for example, in the numberof directions in which current can be detected, thereby increasing thedata suitable for use in an inversion to derive the localized formationtensor. The selected emitter electrodes provide a static or lowfrequency E-field (e.g., <100 Hz) to generate a localized current flowin the surrounding formation. The current can flow to a distant returnelectrode or between two selected emitter electrodes, and appropriateswitching enables sufficient measurements to be obtained for the tensorinversion. The focusing electrodes can be enabled or disabled to varythe depth of penetration of the current into the formation, therebyproviding additional measurements. The measurements obtained by theselected sensor electrodes may be voltage differentials or absolutevoltages relative to the tool ground.

It should be noted that while the above embodiments are described withinthe context of wireline logging tool transducer pads that contact theborehole wall, the emitter and sensor configurations described may alsobe used with LWD tools such as that shown in FIG. 4A. In such LWD toolembodiments, the resistivity of the drilling fluid and the standoffdistance between the transducers and the borehole wall can affect thesampled measurements, but both of these parameters may also be accountedfor by the inversion process described in more detail below.

As previously noted, emitter and sensor electronics modules within thetransducer pad coupled to electronics within the tool body. Theillustrative embodiment of FIG. 10 illustrates an example of ananisotropy imaging system 1100, and shows both the downhole systemelectronics (including the tool body electronics) and surface systemelectronics. Downhole system 1120 includes four transducer pads 1140(similar to those already described) that each includes emitters 1146coupled to emitter electronics module 1142, and sensors 1148 coupled tosensor electronics module 1144. The emitter and sensor electronicsmodules couple to and communicate with downhole hardware interfacemodule 1138 within tool body 1130, which provides an interface betweenthe transducer pads 1140 and downhole processor 1134.

Downhole processor 1134, which can include any of a wide variety ofprocessors and/or processing subsystems, executes software that performsat least some of the control and data acquisition tasks associated withcontrolling and acquiring data from transducer pad 1140. The softwareexecuting on downhole processor 1134, as well as the acquired data, isstored on downhole memory/storage module 1136, which couples to downholeprocessor 1134 and can include any known data storage technologysuitable for use in a downhole tool environment. Downhole processor 1134also couples to downhole/surface interface module 1132, which in turncouples to surface/downhole interface module 1114 within surface system1110 to provide a communication link between surface system 1110 anddownhole system 1120.

Surface system 1110 includes surface processor 1116, which couples touser interface 1112, surface/downhole interface module 1114 and surfacememory/storage module 1118. Surface processor 1116 executes softwarestored within surface memory/storage module 1118 that performsprocessing on the data provided by downhole system 1120 viasurface/downhole interface module 1114. Surface memory/storage module1118 may be any of a wide variety of memory and/or storage device, orcombinations thereof, and provides both short-term (e.g., while thesystem is powered up) and long-term (e.g., during periods when thesystem is powered down) program and data storage. Data provided bydownhole system 1120, as well as data processed by surface processor1116, may be stored on surface memory/storage module 1118. Userinterface 1112 allows a user to interact with surface system 1110 (andoverall with anisotropy imaging system 1100), providing both inputdevices suitable for entering commands (e.g., a mouse and keyboard) andoutput devices for displaying windows, menus and data to a user (e.g.,displays and printers).

The data acquired by downhole system 1120 is processed to deriveanisotropy data that can be presented to a user of system 1100. Theprocessing is distributed between surface system 1110 and downholesystem 1120, and the present disclosure does not limit how thatdistribution may be implemented. However, for purposes of describing thefunctionality of the processing, the illustrative embodiment presentedperforms the data acquisition and inversion operations described belowwithin downhole system 1120, and data logging, presentation andlong-term storage within surface system 1110.

As previously noted, each of the measurement samples processed byanisotropy imaging system 1100 can be represented by a measurementtensor M(z,Φ_(t)) with measurement tensor components M_(ij)(z,Φ_(t)).For each measurement tensor component, i={x,y,z} and represents theorientation of the active emitter when the measurement was taken,j={x,y,z} and represents the orientation of the sensor that performedthe measurement, z is the borehole depth, and Φ_(t) is the azimuthalangle relative to the tool axis. The flow of the measurement tensor dataas it is processed by anisotropy imaging system 1100 is shown in FIG.11. A measurement tensor is received (block 1202) and the measurementtensor component values are adjusted to account for calibration andtemperature corrections (block 1204). In some cases where theconductivity of the formation behaves linearly, it may also be possibleto adjust the measured values (block 1204) to control the radial andvertical resolution of the measurements using software focusing filters.Such filtering can also reduce the effect of the borehole wall and thestandoff of the tool from the borehole wall (e.g., when incorporatedinto an LWD tool). Software focusing is well known in the art and notdiscussed further.

Once the measurement tensor component values have been adjusted (block1204) an inversion process is performed (block 1208) whereby theadjusted measurement tensor component values are iteratively comparedagainst reference tensor component values from a library (block 1206) oragainst reference tensor component values produced by a forward model(block 1210). The formation parameters for the library and/or modelreference tensor component values associated with the smallest tensordifference (described in more detail below) are provided to surfacesystem 1110 as the formation parameter values associated with the depthand azimuth angle of the adjusted measurement tensor. Surface system1110 then present the data to the user (block 1212) as, for example, thegraphical logs of FIG. 12. The data and the logs may both be saved onsurface memory/storage module 1118 for later retrieval and or additionalprocessing. In at least some illustrative embodiments, a combination ofa library lookup and a forward model calculation may be used. Forexample, comparisons with a library may be used to identify one or moreparameter value ranges (horizontal and vertical resistivity, relativedip, relative strike, etc.), after which the model is iterativelyapplied over that range to identify modeled reference tensor componentvalues that more closely match the adjusted measurement tensor componentvalues.

The reference tensor component values provided by either a library or aforward model are compared against the adjusted measurement tensorcomponent values by calculating a normalized tensor difference betweenan adjusted measurement tensor and a library-supplied or model-generatedreference tensor. This different magnitude is iteratively computed foreach reference tensor from the library or the model until a minimumdifference magnitude is identified. The parameter values correspondingto the library/model reference tensor that produces the minimumdifference magnitude are provided as the parameters of the formationcorresponding to the borehole depth and azimuth of the adjusted measuredtensor. In at least some illustrative embodiments this relationship isexpressed as follows:

$\begin{matrix}{\left\lbrack {{R_{h}\left( {z,\Phi_{t}} \right)},{R_{v}\left( {z,\Phi_{t}} \right)},{\theta\left( {z,\Phi_{t}} \right)},{\Phi\left( {z,\Phi_{t}} \right)}} \right\rbrack = {\arg_{R_{h},R_{v},\theta,\Phi}\left\lbrack {\min\left( {\frac{{M_{ij}^{ref}\left( {R_{h},R_{v},\theta,\Phi} \right)} - {M_{ij}^{adj}\left( {z,\Phi_{t}} \right)}}{M_{zz}^{ref}\left( {R_{h},R_{v},\theta,\Phi} \right)}} \right)} \right\rbrack}} & (1)\end{matrix}$

where,

-   -   R_(h) is the horizontal resistivity;    -   R_(v) is the vertical resistivity;    -   θ is the relative dip (to the tool);    -   Φ is the relative strike (to the tool);    -   Φ_(t) is the tool measurement azimuth;    -   z is the borehole depth;

M_(ij) ^(ref) is the reference tensor component ij (library or model);

-   -   M_(ij) ^(adj) is the adjusted measurement tensor component ij;    -   i is the tensor component orientation index {x,y,z} of the        emitter; and    -   j is the tensor component orientation index {x,y,z} of the        sensor.        As previously noted the indices indicate the orientations of the        active emitter when the measurement was taken and of the sensor        providing the measurement. Thus, for example, M_(zz) ^(ref)        represents a reference measurement for an active emitter and a        sensor both oriented in the z direction (here used for        normalization). Similarly, M_(xy) ^(adj) is an adjusted        measurement taken by a sensor oriented along the y axis while an        emitter oriented along the x axis was active. Measurements can        include, but are not limited to, voltage, current, magnetic        field strength and electric field strength. For example, in the        embodiment of FIG. 8, voltage measurements may be provided by        each of the sensor coils 814 and compared against similar        reference voltage measurements.

It should be noted that to fully characterize the anisotropy of theborehole measurements, both the tool measurement azimuth Φ_(t) as wellas the formation strike Φ^(abs) with respect to earth are needed. In atleast some illustrative embodiments the formation strike Φ^(abs) isderived from the tool measurement azimuth Φ_(t) and the relativeformation strike Φ using the following conversion equation:Φ^(abs)(zΦ _(t))=φ(z,Φ _(t))−Φ_(t)  (2)Also, additional parameters may be included in and provided by thelibrary and/or the model. Such parameters may include, for example, thestandoff distance between the transducer pad and borehole wall and themud resistivity for embodiments where the emitters and sensors do notcontact the wall.

The dielectric constant of the formation may also be included in andprovided by the library and/or model through the use of multiplemeasurements taken at different frequencies. At lower frequencies theresponse is primarily due to the resistivity of the formation, while athigher frequencies the response is primarily due to the reactance of theformation. In at least some embodiments, additional measurements aremade in various directions as before but at multiple frequencies,enabling the anisotropy of the dielectric constant to also becharacterized. This characterization may be derived from either a secondseparate measurement tensor that includes the additional measurementsfor each sample at a given azimuth and depth, or from a single higherorder measurement tensor that includes sufficient components to deriveboth the electrical resistivity and permittivity anisotropy of theformation. Anisotropic resistivity and dielectric values may also beconverted into properties of individual layers that make up laminationspresent in the formation. For example, horizontal resistivities,vertical resistivities, dielectric constants and their volumetric ratiosmay be used to identify shale and sand layers. Because the systems andmethods described enable the measurements to be resolved into at leastthree orthogonal directions (e.g., two horizontal and one vertical),more complex laminations and formations may be identified andcharacterized.

FIG. 13 shows an illustrative method for using the tools and systemsdescribed above. An illustrative borehole imaging tool is lowered intothe borehole (block 1402), and as it is pulled back up the borehole, thetool periodically induces fields in three different directions withinthe formation for a given depth and azimuth angle, each field inducedduring three separate time periods (block 1404). During each timeperiod, field measurement samples are taken in all three directions(block 1406). The measurements may be electric field measurements ormagnetic field measurements (or both), and may be expressed eitherdirectly as field strength measurements or indirectly as correspondingelectrical current or electric potential measurements. A measurementtensor is produced (e.g., a 3×3 voltage measurement tensor) that isassociated with a given borehole depth and tool azimuth angle (block1408). The borehole characteristics at the given depth and azimuth angleare derived from the measurement tensor (block 1410) by using, forexample, the inversion process described above. The derived data is thenpresented to a user of the tool (block 1412), ending the method (block1414). FIG. 12 (previously described) shows an illustrative example ofthe types of two-dimensional log formats that can be used to present thedata to a user.

Numerous other modifications, equivalents, and alternatives will becomeapparent to those skilled in the art once the above disclosure is fullyappreciated. For example, although three orthogonal emitters and sensorsare used in a tri-axial configuration in the embodiments described,different numbers of emitters and/or sensors may also be used, and suchemitters and/or sensors may be configured in a non-orthogonalorientation. Also, additional focusing and guard rings may be added tothe galvanic transducer pads described to provide additional controlover the direction of the current flowing through the formation to/fromsuch transducer pads. Further, although each type of emitter and sensor(galvanic, capacitive and inductive) was discussed individually, atleast some embodiments combine several of these into a single instrumentand include combined concurrent measurements within the measurementtensors. The programmable downhole processor is just one example of asuitable downhole controller, and it could be replaced or augmented withan integrated or hardwired controller. It is intended that the followingclaims be interpreted to embrace all such modifications, equivalents,and alternatives where applicable.

What is claimed is:
 1. A downhole imaging tool that comprises: downholeemitters that sequentially induce, at azimuthally-spaced positions, aplurality of fields having components in non-coplanar directions withina formation; directionally sensitive downhole sensors that concurrentlysense, in non-coplanar directions, the components caused by eachemitter; and a downhole controller that processes signals received fromthe directionally sensitive downhole sensors to provide a plurality ofmeasurement sets, wherein each measurement set is represented by animpedance tensor greater than 2×2 at each of said azimuthally spacedpositions; wherein the controller derives a mud resistivity and astandoff distance, between the tool and a borehole, associated with aborehole depth and an azimuth angle.
 2. The tool of claim 1, wherein theimpedance tensor is real-valued to indicate anisotropic resistivity orconductivity.
 3. The tool of claim 1, wherein the impedance tensor isimaginary-valued to indicate anisotropic electric permittivity.
 4. Thetool of claim 1, wherein the impedance tensor is complex valued toindicate anisotropic resistivity and electric permittivity components.5. The tool of claim 1, wherein said plurality of fields are electricalfields.
 6. The tool of claim 1, wherein said plurality of fields aremagnetic fields.
 7. The tool of claim 1, wherein the downhole emitterscomprise three orthogonal coils.
 8. The tool of claim 7, wherein thedownhole sensors comprise three orthogonal coils.
 9. A downhole imagingtool that comprises: a tool body that moves along a borehole through aformation with sensing surfaces to measure formation impedance tensorsas a function of borehole depths and azimuth angles, wherein eachsensing surface comprises a set of electrodes with multiple orthogonalsensing electrodes that sequentially provide an electrical current andmultiple orthogonal sensing electrodes that concurrently acquire aplurality of measurement sets for which each measurement set isrepresentative of three linearly independent directional components of aresulting electrical field in the formation at the borehole depth andazimuth angle at which each measurement set is acquired; and a downholecontroller that processes signals received from the sensing electrodesto provide a set of measurements represented by an impedance tensorgreater than 2×2 at each of the borehole depths and azimuth angles;wherein the controller derives a mud resistivity and a standoffdistance, between the tool and the borehole, associated with a boreholedepth and an azimuth angle.
 10. The tool of claim 9, wherein theimpedance tensor indicates anisotropic resistivity or conductivity. 11.The tool of claim 9, wherein the impedance tensor indicates anisotropicelectric permittivity.
 12. The tool of claim 9, wherein the impedancetensor is complex valued to indicate anisotropic resistivity andelectric permittivity components.
 13. The tool of claim 9, furthercomprising: a plurality of downhole electrode sets; a downhole emitterelectronics module coupled to the downhole controller; a downhole sensorelectronics module coupled to the downhole controller; a switch coupledto the plurality of downhole electrode sets, the downhole controller,the downhole emitter electronics module and the downhole sensorelectronics module; wherein the downhole controller commands the switchto selectively couple at least a first electrode set of the plurality ofelectrode sets to the emitter electronics module and operates the firstelectrode set as emitters; and wherein the downhole controller commandsthe switch to selectively couple at least a second electrode set of theplurality of electrode sets to the sensor electronics module andoperates the second electrode set as the sensing electrodes.
 14. Thetool of claim 13, further comprising: one or more focusing electrodespositioned adjacent to at least one signal electrode operating as anemitter and selectively shorted to said at least one signal electrode.15. The tool of claim 9, further comprising a computer system thatreceives and derives from the set of measurements one or more formationcharacteristics associated with the given borehole depth and azimuthangle and further presents to a user data representative of at least oneof the one or more borehole characteristics.
 16. An imaging method thatcomprises: lowering a downhole imaging tool into a borehole through aformation; at each of multiple azimuth angles on the borehole wallsequentially inducing fields having three linearly-independentdirectional components, one component per field, within a formation;detecting the directional field components, using linearly-independentdirectional downhole sensors that concurrently sense the components ofeach field, to obtain a plurality of measurement sets, wherein eachmeasurement set is a function of azimuthal angle and depth in theborehole, and is further represented by an impedance tensor greater than2×2; deriving from the measurement sets one or more formationcharacteristics, comprising a mud resistivity and a standoff distance,between the tool and the borehole, as a function of said azimuthal angleand depth in the borehole; and presenting to a user data representativeof the one or more borehole characteristics.
 17. The method of claim 16,wherein the impedance tensor indicates anisotropic resistivity orconductivity.
 18. The method of claim 16, wherein the impedance tensorindicates anisotropic permittivity.
 19. The method of claim 16, whereinthe impedance tensor is complex valued to indicate anisotropicresistivity and permittivity components.
 20. The method of claim 16,wherein the one or more formation characteristics comprise acharacteristic selected from the group consisting of a verticalformation resistivity, one or more horizontal formation resistivities, aformation dip, and a formation strike.